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Carbon dioxide (CO2) flooding has been demonstrated as an economically feasible technique for carbon capture and storage (CCS) via enhanced oil recovery (EOR). In the oil industry, most of the CO2-EOR projects were implemented in miscible phase (CO2 miscible flooding), and it has become the most productive EOR method in the United States since 2012. Successful implementation of CO2 miscible flooding requires comprehensive guidelines about where CO2 can be applied. With the development of new technology, the suitable conditions for CO2-EOR have changed. Therefore, updating the guidelines for CO2-EOR is necessary. In this study, we updated the guidelines for field CO2 miscible applications in the United States by collecting valuable information from about 100 publications. Significant parameters for CO2 miscible flooding such as minimum miscibility pressure (MMP) and pay zone net thickness were considered for the first time in comparison with existing research studies. After data processing/cleaning, 207 projects have remained in the dataset. Combination plots were created to explore the ranges, distributions, and cumulative frequencies of each property. Meanwhile, descriptive values were calculated based on statistical methods. The guidelines for CO2 miscible flooding were presented with important parameters, including porosity, permeability, depth, reservoir temperature, net thickness, oil saturation, oil gravity, oil viscosity, and MMP. The analyzed results show that the reservoir pressure should be greater than 1020 psi to achieve miscibility, and CO2 miscible flooding project could be successfully applied in a reservoir with an oil gravity greater than 25 °API, oil viscosity less than 4 cp, and a reservoir temperature less than 120 °F.

Surfactants have been the widely used agents to alter the wettability of carbonate rocks to more water-wet and enhanced oil recovery (EOR). As one of major EOR methods, an effective surfactant huff-puff application design requires comprehensive guidelines about where, how, and when this method could be applied. In order to construct such guidelines, a dataset including 338 effective surfactant imbibition tests is established by collecting information from nearly 50 publications. Based on this dataset, descriptive statistical analysis methods are used to conduct data analysis, including three main parts. The first part establishes the application guidelines for surfactant huff-puff treatments which displays suitable application ranges of critical parameters regarding rock, oil, and water. Results show that surfactants can be effectively applied in wide ranges: porosity from 3.1 to 51.7%, permeability from 0.04 to 1458 mD, starting oil saturation from 37.7 to 100%, temperature from 20 to 100 °C, average contact angle from 55 to 180°, oil gravity from 22 to 75.2 °API, oil viscosity from 0.3 to 23 cp, acid number from 0 to 4.5 mg KOH/g oil, base number from 0 to 1.83 mg KOH/g oil, asphaltene concentration from 0 to 10.7 wt%, salinity of connate water and imbibition water from 0 to 263.7 g/l, divalent cations concentration of connate water and imbibition water from 0 to 24.6 g/l. The second part discusses several aspects about design of surfactant huff-puff treatments. Results show that anionic, cationic, and nonionic surfactants have been applied in 83% of tests. Among them is cationic surfactants which have the most frequency. Surfactant concentration is suggested to be remained close or above a critical concentration to obtain the best performance. It is shown that 97% of tests are conducted with surfactant concentration less than 2.0 wt%. In addition, blends of different surfactants and usage of additives could enhance the effectiveness of surfactants. The last part evaluates the performance of surfactant imbibition tests. Results show that surfactants are capable to improve oil recovery either from secondary phase or tertiary phase. In general, the range of oil recovery from secondary phase and tertiary phase are similar, which covers from 1.0 to 93%. However, the average oil recovery from secondary phase is 39.1% which is higher than 32.2% from tertiary phase. Based on this, it is recommended that the treatment timing should be considered in the design of treatments.

Improved Oil Recovery (IOR) techniques in Unconventional Liquids Rich Reservoirs (ULR) are still a new concept because there is no commercial project for any IOR technique so far. Carbon dioxide (CO2) based EOR technique has been effectively applied to improve oil recovery in the tight formations of conventional reservoirs. Extending this approach to unconventional formations has been extensively investigated over the last decade because CO2 has unique properties which make it the first option of EOR methods to be tried. However, the applications and mechanisms for CO2-EOR in unconventional reservoirs would not necessarily be the same as in conventional reservoirs due to the complex and poor-quality properties of these plays. Since the first CO2-EOR huff-n-puff project was conducted in conventional reservoirs in Trinidad and Tobago in 1984, more than 130 additional projects have been put in operation around the world, mainly located in USA, Turkey, and Trinidad and Tobago. In this study, we combined Production Data Analysis (PDA) for the production data of these projects with numerical simulation methods to produce one typical graph accounts for the main mechanisms controlling CO2-EOR performance in conventional reservoirs. On the other hand, we have couple of CO2-EOR huff-n-puff pilot tests conducted in Bakken formation between 2008 and 2016. Two engineering-reversed approaches have been integrated to produce a unique type curve for the performance of CO2-EOR huff-n-puff process in shale oil reservoirs. Firstly, a numerical simulation study was conducted to upscale the reported experimental-studies outcomes to the field conditions. As a result, different forward diagnostic plots have been generated from different combinations for CO2 physical mechanisms with different shale-reservoirs conditions. Secondly, different backward diagnostic plots have been produced from the history match with CO2 performances in fields’ pilots performed in some portions of Bakken formation located in North Dakota and Montana. Finally, fitting the backward with the forward diagnostic plots was used to produce another unique type curve to represent CO2-EOR performance in shale oil reservoirs. This study found that the delayed response in the incremental oil production resulted from CO2 injection in shale reservoirs is mainly function of CO2 molecular diffusion mechanism. On the other hand, the CO2 diffusion mechanism has approximately no effect on CO2-EOR performance in conventional reservoirs which have a quick response to CO2 injection. This finding is very well consistent with the experimental reports regarding the role of diffusion in conventional cores versus shale cores. In addition, this study found that kinetics of oil recovery process in productive areas and CO2-diffusivity level are the keys to perform a successful CO2-EOR project in shale formations. This paper provides a thorough idea about how CO2-EOR performance is different in the field scale of conventional reservoirs versus shale formations.

The recovery from fractured reservoirs is usually low. The areal heterogeneity is one result of the fractured reservoir. Low salinity waterflooding (LSWF) and preformed particle gel (PPG) have recently drawn great interest from the oil industry. LSWF can only increase displacement efficiency, and it has little or no effect on sweep efficiency whereas PPG can plug fractures and improve sweep efficiency, but they have little effect on displacement efficiency. The coupled method bypasses the limitations of each method when used individually and improves both displacement and sweep efficiency. The main objective of this study was to determine whether the combining technologies can improve conformance control in fractured sandstone reservoirs. Before the study was conducted, the effects of low salinity waterflooding, number of fractures, and PPG strength were studied. The PPG was injected into the fracture at a flow rate 2.0 ml/min. Brine was injected at a different flow rate after PPG placement to test the effect of flow rate on the PPG’s plugging efficiency. Laboratory experiments showed that the oil recovery factor and the Frrw increased when the concentration of injected brine changed from conventional salinity to low salinity and the areal sweep efficiency was improved. However, the PPG extruded pressure decreased when the PPG swelled in a low-brine concentration. At a high-flow rate, there was no significant effect on the Frrw. Combining two different EOR technologies can improve displacement and sweep efficiency and, in turn, enhance conformance control.

The oil recovery from fractured reservoirs is usually low, which is usually caused by the existence of areal formation heterogeneity. Two existing enhanced oil recovery (EOR) technologies, low salinity water flooding (LSWF) and preformed particle gel treatment (PPG), have recently drawn great interest from the oil industry. We integrated both of these technologies into one process to improve both oil displacement and areal sweep efficiency. The objective of this study was to test how the integrated method could be used effectively to increase oil recovery and control water production. The semi-transparent five-spot models, which were made of sandstone cores and acrylic plates, were built. We investigated the effect of four parameters on the improvement of oil recovery and areal sweep efficiency of oil, including gel strength, water salinity, injection rate, and number of fractures. Two approaches were followed during core flooding, sequential mode and mixed mode. The result shows that PPG and LSW injected together as one mixture improved oil recovery factor more than the first approach. PPGs plugged the fractures and successfully improved areal sweep efficiency; however, they have little effect on displacement efficiency. LWSF increased displacement efficiency but had little or no effect on sweep efficiency. The integrated methods bypassed the limitations of each method when used individually and improved both displacement and sweep efficiency.

Oil recovery from carbonate reservoirs is usually low due to their extreme heterogeneity caused by natural fractures and the nature of the oil-wet matrix. Low salinity water flooding (LSWF) and preformed particle gels (PPG) control conformance are two novel technologies that have recently drawn great interest from the oil industry. Theoretically, LSWF can only increase displacement efficiency, and it has little or no effect on sweep efficiency; PPG can plug fractures, they can improve sweep efficiency, but they have little effect on displacement efficiency. We developed a cost-effective, novel, enhanced oil recovery (EOR) technology for carbonate reservoirs by coupling the two technologies into one process. The objective of this paper is to provide a comprehensive understanding of the combined technology and to demonstrate how the coupling method can improve oil recovery. The oil-wet carbonate cores provided a higher improved oil recovery than water-wet carbonate cores during LSWF. The decrease in fracture width resulted in a higher oil recovery factor. Compared to traditional bulk gel treatments, PPG forms stronger plugging but will not form an impermeable cake in the fracture surface; therefore, PPG allows low salinity water to penetrate into the matrix to modify its wettability, thereby producing more oil from the matrix. Results also show that oil recovery increased by 10% during LSWF after the second water flooding. Additionally, when PPGs were injected, another 4% of oil recovery was gained. As a result, the combined LSWF and PPG increased oil recovery by 18%. A full-factorial experimental design was performed to investigate the influence of the PPG-placed injection pressure (which refers to the maximum pressure used to inject PPG for each experiment), water salinity, and fracture width. Experimental results tell that PPG-placed injection pressure is the factor that strongly influences both oil recovery factor and residual resistance factor; fracture width is the least influential factor among the three. Experimental results prove that the coupled method bypasses the limitations of each method when used individually and improves both displacement and sweep efficiency.

Excess water production is a major problem in water-flooded mature oilfields. Recently, using microgel treatment as a conformance control method to reduce water production has drawn increasing attention in oil industry. The success of microgel treatments highly depends on in-depth understanding where and when microgel can be successfully applied, how to design the injection parameters, and how well the performances of microgel treatments in different reservoir conditions. To better solve these problems, a total of 154 field application data from microgel-treated injection wells was collected from 2005 to 2016. These data are statistically analyzed by using histograms, boxplots, and scatterplots. Histograms are used to analyze the reservoir and well characteristic data in order to find out where and when microgels are generally used. Scatterplots are used to uncover some general trends that can guide field engineers to design injection parameters and improve the treatment performances. Boxplots compare the injection parameters among different types of reservoirs and outline special cases that are far different from the majority of the cases. These special cases are further studied because they contain additional information during the treatment. Throughout the comprehensively data analysis, the application guidelines for microgel treatments are presented, which includes screening guidelines, design considerations, and treatment performances. The instructional guidelines can help to maximize the likelihood of microgel treatment projects being technically successful.

Polymer solutions and gels are frequently used to control excessive water production in oil and gas wells by reducing the permeability to water flow to a greater extent than to oil or gas flow (Relative Permeability Modifiers, RPM, or disproportionate permeability reduction, DPR). RPM and DPR can be used as synonymous in this study; however, specialists use RPM term for the cases in which permeability reduction is less compare to DPR. The significance of RPM agents, chemicals using in water-shutoff treatments, is that their placement does not require mechanical isolation. However, the performance of RPM treatment is still poor in field applications. This study applied numerical simulation methods to investigate the factors impacting RPM treatments on reservoir (Macroscopic) level. Furthermore, Design of Experiments (DOE) was used to rank these factors based on their influence on RPM performance (water cut reduction and oil recovery improvement). The results indicated that there are nine parameters which can enhance or downgrade the success of DPR treatments, treatments at oil/gas wells when use of DPR polymer or gel results in Disproportionate Permeability Reduction of treated formation. The performance of DPR treatment was more pronounced at low oil density, low oil viscosity, high gel penetration depth, and at high permeability heterogeneity among layers (linear flow is more dominated). However, the performance of DPR treatments was downgraded if the treatments were applied at high production flowrate, low ratio of residual resistance factor for water (Frrw) to residual resistance factor for oil (Frro), and high G-shape (crossflow indicator) values. Moreover, when the capillary forces dominate the flow (capillary-viscous number > 10), RPM results were not largely encouraging due to water blocking effect. On the other side, in the viscous dominated flow, RPM performance was more pronounced. These factors which were studied in this work can promote a short-term successful remedy, a long-term successful treatment, or even a failed treatment. Some of these factors can be controlled; the operator can choose the optimum level of the parameter, like production flowrate. However, other factors cannot be controlled, but the value of this study is still increase probability of success the treatment prior to field application.

The effect of gas-wetting on the liquid-blocking effect near a wellbore region is significant. Here, we functionally modified nano-silica particles with a size of approximately 40 nm each by using a fluorosurfactant and obtained a super gas-wetting nano-silica particles, which could improve the contact angles of brine and hexadecane from 23° and 0° to 152° and 140°, respectively, and decrease the surface free energy of rock surface from 72 to 1.6 mN/m. The decrease in the gas displacement was approximately 30%. FT-IR, SEM and EDS were employed to determine the morphological change in the rock surface before and after gas-wetting alteration. Results indicate that when the fluorosurfactant molecules are joined to the nano-silica surface, and C F bond is recognized. The grape-like particles forming a multi-adsorption on the rock surface, which play an important role in super gas-wetting by decreasing surface free energy and increasing roughness on the rock surface. The data of EDS was consistent with the results of FT-IR and SEM. To further understand the influence of gas-wetting alteration on the flow and distribution of fluids in porous media, visualization flooding was conducted. The results show that the initial liquid saturation in the micromodel decreased sharply from 33.23% to 20.77% after the gas-wetting treatment, and the contact angle of isolated brine droplet on the treated pore-wall was approximately 125°, which also verifies that pore wettability can be altered to gas-wetting. The analytical data of the oil displacement experiment demonstrates that the substantial decrease in oil saturation may contributes to enhancing oil recovery. Furthermore, the mobility of oil trapped in micro channels can also be enhanced significantly after gas-wetting alteration due to the presence of methane.

The relative permeability is a key parameter for describing multiphase flow in porous media. In this paper, a series of experiments were conducted to study the impact of displacement pressure gradient (DPG) to relative permeability curves using five cores from Shengli Oilfield. Then, an empirical model was proposed to consider the impact of DPG. Finally, the numerical simulation model was established by introducing empirical correction formula into the traditional black oil model, and the effect of DPG on reservoir performance was analyzed. Result shows that with the increase of the DPG (in a range of 0.125–0.498 MPa/m), the residual oil saturation decreases, the cross point of water and oil relative permeability curves moves to the right, and the relative permeability for water phase increases under the same water saturation. In the type III relative permeability curve, with the decrease of DPG, the water relative permeability decrease and the oil relative permeability keeps the same. With considering correction of relative permeability will improve the recovery factor and simulation accuracy.

Unconventional tight sandstone reservoirs have been developed during recent years and a large number of multi-stage fractured horizontal wells have been drilled to stimulate reservoir performance. However, fluid flow in low permeability porous media no longer obeys Darcy’s law and instead conforms to low-velocity non-Darcy flow. Most commercial numerical simulation software for multi-stage fractured horizontal well development may cause inaccuracy in simulating performance of tight sandstone reservoirs. In this paper, the investigation of existing conditions of low velocity non-Darcy flow for oil flow in irreducible water saturation tight sandstone cores was conducted and discussed through lab-experiments. And existence of low velocity non-Darcy flow was proven. Then, based on the low velocity non-Darcy flow model, the multistage fractured horizontal well numerical simulator was developed and verified. The comprehensive comparison and analysis of the simulation results of Darcy flow and non-Darcy flow were presented including liquid production rate, oil production rate, water cut, reservoir pressure, oil saturation distribution, and dimensionless permeability coefficient. With considering the non-Darcy flow, the fluid flow in reservoir consumes more driving energy and the water flooding efficiency was reduced. Finally, a multistage fractured horizontal well water injection pilot test in Fan-116 block was analyzed to perform the non-Darcy flow numerical study on an actual tight sandstone reservoir. The results show that for the tight sandstone reservoir, the optimal water injection time is when the average reservoir pressure declined to 26.92 MPa based on maximizing the total field oil production in 15 years. This pressure level is close to the hydrostatic pressure and the optimized recovery is 20.51% in the final simulation time. This approach is an initial exploration for the “multi-stage fractured horizontal well development for tight sandstone reservoirs considering non-Darcy flow” and could be applied to other tight oil/gas reservoirs.

Large volumes of fracturing fluid are required in shale slickwater fracs, and a considerable amount of polymer friction reducer would remain in microfractures if the polymer has not been broken before gas production. It is of major interest to evaluate the effect of polymer on water/gas flow behavior in the microfractures of shale reservoirs. We fabricated six shale fracture models with different fracture widths and set up a core flooding apparatus to conduct brine/gas-injection experiments before and after polymer treatment. A method by which to calculate the residual resistance factor for gas ( F rr,gas ) was defined. The experimental results illustrate that polymer can reduce the permeability to water more than to gas. In the first cycle of brine/gas injection experiments after polymer treatment, the residual resistance factor for brine ( F rr,water ) and F rr,gas exhibited power-law characteristics through their shear rate and superficial gas velocity, respectively. The F rr,water and F rr,gas tended to decrease as the fracture width grew. Surprisingly, polymer treatment does not impair gas flow in wider fractures, and may even improve it. The mechanisms responsible for disproportionate permeability reduction (DPR) in the fractured shales were proposed in this paper.

Unlike conventional gas reservoirs, gas flow in shale reservoirs is a complex and multiscale flow process which has special flow mechanisms. Shale gas reservoirs contain a large fraction of nano pores, which leads to an apparent permeability that is dependent on pore pressure, fluid type, and pore structure. Study of gas flow in nano pores is essential for accurate numerical simulation of shale gas reservoirs. However, no comprehensive study has been conducted pertaining to the gas flow in nano pores. In this paper, experiments for nitrogen flow through nano membranes (with pore throat size: 20 nm, 55 nm, and 100 nm) have been done and analyzed. Obvious discrepancy between apparent permeability and intrinsic permeability has been observed; and the relationship between this discrepancy and pore throat diameter (PTD) has been analyzed. Then, based on the advection-diffusion model, a new mathematical model has been constructed to characterize gas flow in nano pores. A new apparent permeability expression has been derived based on advection and Knudsen diffusion. A comprehensive coefficient for characterizing the flow process was proposed. Simulation results were verified against the experimental data for gas flow through nano membranes and published data. By changing the comprehensive coefficient, we found the best candidate for the case of argon with a membrane PTD of 235 nm. We verified the model using experimental data with different gases (oxygen, argon) and different PTDs (235 nm, 220 nm). The comparison shows that the new model matches the experimental data very closely. Additionally, we compared our results with experimental data, the Knudsen/Hagen–Poiseuille analytical solution, and existing models available in the literature. Results show that the model proposed in this study yielded a more reliable solution. Shale gas simulations, in which gas flowing in nano pores plays a critical role, can be made more accurate and reliable based on the results of this work.

Tight formations with extremely low matrix permeabilities, such as gas shale, can produce at economical rates is due to the inborn fissures and fractures introduced during hydraulic stimulation. These microfractures have much more contact area with the matrix and therefore hold the majority of the productivity potential of shale gas. Slickwater fracturing has been proved to be an effective method by which to increase the recovery of shale gas reservoirs. And friction reducer is the primary component of this fluid. However, the flow characteristics of this solution in microfractures are not clear. Micro-sized fluidic chip was used to represent the microfracture. Friction reducer solution is a shear thinning fluid. Rather than reducing flowing friction, with 0.075 vol% of this fluid flowing in a 1000 μm height, 50 μm width and 4.14 cm length microfracture, the injection pressure increased more than 50%. The impact of the solution concentration was found to be more obvious at low velocities. If a flowback additive is considered for slickwater fracturing, its performance at low velocity or low shear rate would be critical. At the same shear rate, the apparent viscosity is higher in large microfractures. At the same velocity, large microfractures display higher residual resistance factors. Through the analysis of fluid emulsion particle size and gas shale matrix pore size, this friction reducer solution will not go into the matrix pores easily, but can block the pore entrance on fracture face to prevent the fluid from leak off and help pressure build up during slickwater fracturing.

Selecting a proper EOR method for a prospective reservoir is a key factor for successful application of EOR techniques. Reservoir engineers usually refer to screening guidelines to identify potential EOR processes for a given reservoir. However, these guidelines are characterized by poor discriminating powers. In this study, we develop a hybrid scoring system for EOR processes by combining conventional screening guidelines and the random forest algorithm. At first, the screening guidelines were established by compiling 977 EOR projects from various publications in different languages, including Oil and Gas Journal (OGJ) biannual EOR surveys, SPE publications, DOE reports, Chinese publications, etc. Boxplots were used to detect the special cases for each reservoir/fluid property and to present the graphical screening results. To avoid the experts’ bias, the weighting factors for each EOR technique were determined through the application of the random forest algorithm, where the EOR types and the incremental oil recovery were utilized as objective functions. The scoring system was then established by the fuzzification of reservoir/fluid property scores and the computation of composite screening scores. A case study was used to demonstrate that with a simple input of reservoir/fluid information, the novel scoring system could effectively provide recommendations for EOR selection by ranking scores.

Multiple techniques were used to characterize the petrophysical properties of the rock samples from the Fayetteville shale gas play, including clay mineralogy, wettability, organic matter and their maturation, submicron pore structure, and 3-D pore structure. X-ray diffraction (XRD) mineralogy analysis showed high quartz and low clay content in the Fayetteville shale. Wettability tests revealed that the shale surface is originally intermediate-wet and the additives used in hydraulic fracturing fluids can alter shale gas surfaces toward water-wet conditions. The kerogen analysis suggested kerogen type IV and a high level of maturation in the tested samples. Three types of pores were observed through SEM images and the majority of the pores in organic matters were submicron sized (5–100 nm). A three-dimensional pore structure model was reconstructed from 200 two-dimensional SEM/FIB images, and the rock petrophysical properties, including porosity, permeability, and tortuosity, were calculated from the model. In addition, a good agreement was found between the total organic carbon (TOC) computed from SEM images and the TOC measured in the laboratory.